Many light hydrocarbon gas reserves are found in areas of the world that are remote to any markets for the light hydrocarbon gas. Such light hydrocarbon gas is referred to as natural gas. This natural gas may contain condensates that are light gasoline boiling range materials as well as C3–C5 gaseous hydrocarbons and methane.
Frequently such natural gas also contains undesirably high quantities of water, acid gas compounds such as sulfur compounds, carbon dioxide and the like for liquefaction to produce liquefied light hydrocarbon gases, which typically comprise primarily methane and which are frequently referred to as liquefied natural gas (LNG).
When such gases are liquefied, the capacity of the liquefaction plant is determined primarily by the available market for the gas, the availability of transportation to the market and the like. Accordingly in many instances it is desirable to increase the capacity of the liquefaction process in incremental stages as the market expands to remain in balance with the available market. Accordingly light hydrocarbon gas liquefaction processes, referred to herein as natural gas liquefaction processes or LNG processes, are typically installed in trains. The term “train” as used herein refers to a series of vessels capable of, pre-treating and liquefying natural gas. The gas is desirably treated to remove acid gases and water to very low levels prior to charging it to the liquefaction zone. The train also includes compression facilities for compressing the refrigerant required for the refrigeration vessel and the like. The train is an integrated process for producing a selected quantity of liquefied natural gas. Additional trains are added as capacity is required to meet the available market demand and the like.
In FIG. 1, a light hydrocarbon gas liquefaction system and process (train) is schematically shown. The system and process, as shown, includes a refrigeration facility 12. As shown, compressed refrigerant is supplied to facility 12 by turbines 14 and 16, which are shaft coupled by shafts 18 and 20 to refrigerant compressors 22 and 24. Low-pressure refrigerant is supplied to compressors 22 and 24 by low-pressure refrigerant lines 26 and 28. These lines typically return low-pressure refrigerant from facility 12 after it has served its purpose as a refrigerant and has been warmed to a substantially gaseous condition. Compressed refrigerant is supplied via a line 30 to facility 12 and via a line 32 to facility 12. As shown, these lines enter facility 12 at different points. No significance should be attributed to this except that refrigerants can be produced from compressors 22 and 24 at different pressures if desired and passed to facility 12 at different points in the refrigeration process as desired. Spent refrigerant is also shown as recovered through lines 26 and 28 to compressors 22 and 24 respectively. The same or different refrigerants can be used, refrigerants at a different pressures can be used and the like as well known to those skilled in the art.
Further an inlet light hydrocarbon gas which has desirably been treated to remove acid gases and water and is charged to facility 12 via a line 34. A liquefied light hydrocarbon gas is produced through line 36. A wide variety of refrigeration processes are contemplated within the scope of the present invention. No novelty is claimed with respect to the particular type of refrigeration process or vessel used. The process of the present invention is considered to be useful with any type of liquefaction process that requires light hydrocarbon gas as an inlet stream.
Typically a natural gas or other light hydrocarbon gas stream is introduced through a line 40 and passed to an acid gas removal vessel 44. An acid gas regenerator 44 is shown in fluid communication with vessel 46 via lines 38 and 50. The treated gas is typically recovered from vessel 44 through line 48. The recovered gases are passed via a lines 54 and 56 to one or the other of dewatering vessels 58 and 60. Typically vessel 44 is an aqueous amine scrubber and operates as well known to those skilled in the art. The aqueous amine may be selected from materials such as digycolanolamine (DEA), methyldiethanolamine (MDEA), methylethylanolamine (MEA), sulfinol (trademark of Shell Oil Co for amine for acid gas removal) and combinations thereof. The Co2 is typically removed to levels less than about 100 parts per million (ppm) and sulfur is typically removed to levels less than about 16 ppm.
The operation of such acid gas removal vessels, as shown, is well known. Since each train is typically constructed separately as demand requires, it is common to provide an acid gas removal vessel and an acid gas regenerator, for each train.
Since the aqueous amine process produces a gas that is relatively saturated in water and since the water freezes at a temperature much higher than methane, which constitutes the majority of the natural gas stream to be liquefied, it is necessary that at least a major portion of the water be removed. This is typically accomplished by passing the stream containing the water after acid gas removal through lines 54 or 56 into molecular sieve vessels 58 and 60 where the water is selectively removed to produce a dewatered gas that is recovered through lines 62 and 64. This dewatered stream is passed through line 34 into facility 12
In the use of dewatering vessels 58 and 60, one of the vessels is used until it becomes spent and then the flow of gas is switched to the other vessel with the first vessel then being regenerated while the second vessel is in service. Typically two vessels are placed in each train to meet the requirements to dewater the incoming gas. Typically vessels 50 and 60 include an absorption material such as a molecular sieve, activated alumina and the like. This material is effective to remove water from a gaseous stream to extremely low levels and to render the gaseous stream suitable for liquefaction in facility12. Such molecular sieves are typically regenerated by passing a heated gas through the vessel to remove water.
The desulfurization vessels are readily regenerated as well known to those skilled in the art by a variety of techniques. One commonly used technique is the use of a reboiler (not shown) on vessel 46 for the regeneration.
Clearly the construction of separate trains of refrigeration processes as discussed above results in the expenditure of considerable capital to duplicate facilities in each train such as the dewatering and acid gas removal vessels and regeneration vessels. Accordingly a continuing search has been directed to the development of systems and methods for reducing the unnecessary expense for these duplicate vessels.